1. Field of the Invention
The present invention is generally related to processing of high density high sulfur or heavy hydrocarbon crude oil. More specifically, the invention pertains to an improved process for upgrading a heavy hydrocarbon crude oil feedstock into an oil that is less dense or lighter and contains lower sulfur than the original heavy hydrocarbon crude oil feedstock while making value added materials such as olefins and aromatics.
2. Description of Related Art
The invention generally relates to a process for treating a heavy hydrocarbon crude oil, also referred to herein as “crude oil.” More particularly, the process described herein is directed to upgrading a heavy hydrocarbon crude oil feedstock by a hydroprocessing catalyst assisted hydrotreatment. Although the term hydrocracking is often applied to these types of processes, the term hydroconversion (or hydroprocessing or hydrotreatment) will be used herein to avoid confusion with conventional gas oil hydrocracking.
Heavy crude oils are composed chemically of a very broad range of molecules differing widely in molecular weight (MW) and chemical properties. In addition, heavy crude oils from different formations and locations around the world have different characteristics. Because of the large number of variable characteristics of heavy crude oil around the world, it is difficult to define heavy crude oils simply in terms of individual molecular components. Instead, various separation procedures are used to break down the feed into a number of smaller fractions that are more consistently identifiable. One such technique involves separation into solubility classes using solvents of varying polarity and further separation using column chromatography. These fractions can then be further characterized in terms of an average structure by nuclear magnetic resonance (NMR) or other analytical technique known to persons skilled in the art.
Despite the fact that heavy crude oils range widely in their composition and physical and chemical properties, they are typically characterized by having a relatively high viscosity, high boiling point, high Conradson carbon residue, low API gravity (generally lower than 25), and high concentration of sulfur, nitrogen, and metallic impurities. Additionally, the hydrogen to carbon ratio of heavy crude oils is lower than desirable. Further, much of the crude oil around the world also contains relatively high concentration of sulfur. As used herein, the term crude oil, or heavy crude oil, is understood to include heavy hydrocarbon crude oil, tar sands, bitumen, and residual oils, i.e., bottom of the barrel or vacuum bottom oils.
Broadly speaking, heavy crude oils consist of paraffins, cycloparaffins (naphthenes), and aromatics of various ring sizes and degree of aliphatic chain substitution, polarity, and sulfur and nitrogen containing heterocycles content. The molecular weights of heavy crude oils range upward to many thousands of daltons and the boiling points reach 700° C. or more. Most crude oils are believed to be colloidal systems with micelles of high MW polar components (asphaltenes) stabilized by components of intermediate polarity (resins). The asphaltene components contain most of the metals (V, Ni and Fe) complexed by polydentate N and S ligands such as porphyrins.
In the last two decades, environmental and economical considerations have required the development of processes to remove heteroatom such as, for example, sulfur, nitrogen, oxygen, and metallic impurities, from the heavy hydrocarbon crude oil feedstocks; and, to convert the heavy hydrocarbon crude oil feedstocks to lower their boiling points. Such processes generally subject the heavy hydrocarbon crude oils or their fractions to thermal cracking or hydrocracking to convert the fractions having higher boiling points to fractions having lower boiling points, optionally followed by hydrotreating to remove the heteroatoms.
The main features of all hydroconversion processes are similar. Heavy crude oil feedstock is preheated, mixed with hydrogen at pressure, and passed into a reactor kept at reaction temperature. Sometimes part or all of the hydrogen is added directly to the reactor. The residence time of liquid in the reactor can typically range from 1 to 10 hours.
The hydroprocessed products then pass into a series of one or more vapor/liquid separators. Typically, a hot high-pressure separator removes heavy liquid containing pitch and the vapour passes to a cold high-pressure separator to disengage gases from distillate product. Intermediate separators can be employed to reduce temperature and pressure in stages. In some processes, a vapor phase hydrogenation unit is used to further treat the vapour before passing into the cold separator. Gas from the cold separator is then sent to a scrubber or PSA unit to remove H2S and NH3 and light hydrocarbons (which is used as fuel gas) and the hydrogen gas is then recycled to the reactor. Fresh hydrogen, usually produced by steam reforming of methane, is added to make up for the hydrogen consumed.
Technologies for upgrading heavy crude oil, including bitumen and residual oils, to give lighter and more useful oils and hydrocarbons can be broadly divided into two types of processes: carbon rejection processes and hydrogen addition processes. Both of these processes employ high temperatures (usually greater than 400° C.) to “crack” the long chains or branches of the hydrocarbons that make up the heavy hydrocarbon crude oil. In the carbon rejection process, the heavy hydrocarbon crude oil is converted to lighter oils and coke. In some carbon rejection processes, the coke is used elsewhere in the refinery to provide heat or fuel for other processes.
Hydrogen addition processes involve reacting heavy crude oils with an external source of hydrogen resulting in an overall increase in hydrogen to carbon ratio. One benefit of hydrogen addition processes compared to carbon rejection processes is that, in the hydrogen addition process, formation of coke is prevented through the addition of high pressure hydrogen. Examples of hydrogen addition processes include: catalytic hydroconversion (hydrocracking) using active HDS catalysts; fixed bed catalytic hydroconversion; ebullated catalytic bed hydroconversion; thermal slurry hydroconversion (hydrocracking); hydrovisbreaking; and hydropyrolysis.
The main goal of upgrading heavy crude oils is to decrease the molecular weight of large molecules to produce components with boiling points and hydrogen to carbon ratios suitable for liquid fuels. At the same time, contaminants such as sulfur, nitrogen, and metals must be removed and the aromatics saturated. Generally, these different “steps” of upgrading require different processes and processing conditions to achieve the desired properties. For instance, hydrogenation of aromatics is best carried out at moderate temperatures with metal catalysts in the absence of sulfur and nitrogen compounds, while removal of sulfur and nitrogen uses metal sulfide based HDS catalysts that need sulfur and function at higher temperatures. Therefore, the overall process generally involves numerous steps for separation of the heavy crude oil into chemically different components and treating them by the most suitable process for each step. However, economic constraints restrict the use of this approach. Therefore, the only separation normally carried out is distillation to remove light fractions or solvent deasphalting to eliminate asphaltenes. For the reasons discussed herein, the present invention is believed to overcome these economic constraints.
Upgrading heavy oil and residual oils results in formation of free radical chain reactions. Free radicals are highly reactive intermediates which have an unpaired electron. Tertiary alkyl free radicals are more stable than secondary alkyl free radicals and secondary alkyl free radicals are more stable than primary alkyl free radicals. Thus, t-butyl radical (a tertiary radical) is energetically more favoured than the ethyl radical. An example of a free radical reaction pathway is as follows:
1. Initiation:

2. Propagation:


3. Termination

Free radical reactions are influenced by the reactor pressure and, in particular, hydrogen pressure. Consequently, hydrogen pressure is important for hydroprocessing systems. At elevated pressures, i.e., greater than 7 MPa, the reactions followed under low pressure do not generally proceed. Under elevated pressure of hydrogen, hydrogen addition reactions become more favourable. Further, β-scission reactions are less significant under elevated pressure. Therefore, at elevated pressures, rather than multistage cracking via olefin formation, free radicals are stabilized in a single step without formation of olefins. In the intermediate pressure range of 3-7 MPa, a complicated two step mechanism is possible. At lower pressures, cracking reactions form olefins that can be used as fluid catalytic cracking feedstocks.
Thiols, aliphatic sulfides (thioethers), and disulfides are very reactive under thermal conditions and can range as high as 50% of total sulfur in many heavy crude oils bitumens and asphalts. Thermal reactions of these types of sulfur are favorable because carbon-sulfur bonds are weaker than other carbon-carbon bonds. For example,

When thermal cracking occurs in the presence of hydrogen and a catalyst, the reaction pathways change significantly. While thermal cracking still occurs, hydrogenation and hydrogenolysis also occur in parallel, thereby changing the chemical nature of the molecules being cracked. Sulfur and nitrogen are removed from heterocycles producing H2S and NH3 and the formation of carbon-hydrogen bonds. The resultant aliphatic chains can then be cracked to produce light hydrocarbons such as methane, ethane, etc.
Hydrogen can also cap radicals and terminate polymerization reactions, thereby reducing or eliminating coke formation. Therefore, it has been discovered that the partial pressure and purity of hydrogen is significant. As discussed herein, maintenance of high hydrogen pressure in the hydroprocessing unit is needed. However, what is also important is the partial pressure of hydrogen. Accordingly, it is desirable to lower the impurity concentration (light hydrocarbon gases) to maintain a high hydrogen pressure in the hydrotreating unit.
The catalysts normally employed in hydrotreating are metal sulfide based and greatly accelerate hydrodesulfurization reactions leading to low sulfur products. While it is believed that the catalyst do not directly catalyze cracking to any great extent, and it is known that catalysts are easily poisoned by metals normally present in heavy crude oils, the catalysts can still be designed to accelerate cracking reaction. Moreover, even though metal sulfides catalyze hydrogenation of aromatics, because this reaction is reversible and very exothermic, temperatures normally employed to achieve high conversion of material are high, e.g., approximately 450° C. or more, and, thus, tend to favor the reverse reaction (dehydrogenation of aromatics).
Unless operated at high H2 pressure and low LHSV (in order to reduce the temperature and still enable high conversions), most upgrading processes can only achieve low to moderate levels of aromatic saturation. This leads to yields of C1 to C5 hydrocarbon gases which can reach 10 wt % of feed. One of the benefits of this invention is realizing value from these hydrocarbon gases. Because each mole of gas consumes approximately one mole of hydrogen, overall hydrogen consumption can reach 3 wt % of feed (approximately 2000 scf/bbl) in a relatively high pressure process.
All of the foregoing methods involve contacting heavy crude oils with hydrogen at pressure above approximately 1000 psi and temperatures up to 470° C. The heavy crude oil feedstock is thermally cracked and hydrogenated to yield products with increased hydrogen to carbon ratio, reduced sulfur and nitrogen content, and boiling points suitable for refining to various liquid fuels. Generally, the processes can be divided into those employing high activity HDS catalysts based on metals such as Co, Mo, and Ni, which produce low sulfur products, and those using less catalytically active additives or very low concentrations of a more active catalyst designed for coke inhibition and demetallization, which produce higher sulfur products requiring more extensive hydrotreatment. Catalytic promoters such as phosphorus, silica, alkali, and alkali earth metals are also useful.
The prior methods also encounter transport limitations in the upgrading process. Generally, there are two common forms of three-phase (gas, liquid and solid catalysts) reactors are the slurry and trickle-bed (counter flow of liquid and gases over a bed-of catalyst). It is often assumed that the systems are well mixed. In reality, the systems are not well mixed. In fact, formation of gas bubble of hydrogen can impede mass transfer of hydrogen to the catalyst surface. To address this problem, the overall reaction consists of the following sequence of events: mass transport from the bulk concentration in the gas bubble to the bubble-liquid interphase; mass transport from the bubble interface to the bulk liquid phase; mixing and diffusion of in the bulk liquid; mass transfer to the external surface to the catalyst particles; and reaction at the catalyst surface. Although one would expect that introduction of mixing would allow uniform conditions in the bulk liquid, such gas-liquid mixing is often limited. Therefore, the present invention addresses this shortcoming by providing improved mass transport in the upgrading process.
Further, processes for the thermal and catalytic rearrangement of heavy hydrocarbon crude oils and other similar feedstocks is described by de Bruijn et al. in U.S. Pat. Nos. 5,104,516 and 5,322,617, the contents of which are hereby incorporated by reference. In the disclosed processes, a heavy hydrocarbon crude oil or heavy hydrocarbon crude oil feedstock dispersion is reacted with synthesis gas in the presence of a catalyst to reduce the viscosity and density of heavy hydrocarbon crude oil, thus making it more amenable for transportation by a pipeline. The processes disclosed in Bruijn et al. provide for the recovery of hydrogen and carbon dioxide gases as by-products, and the recycling of carbon monoxide back into the rearrangement process. Use of a bifunctional catalyst present in about 0.03 to about 15% under conditions and pressures that facilitate both the gas shift reaction and the rearrangement of hydrocarbons are described. The bifunctional catalyst includes an inorganic base and a catalyst containing a transition metal such as iron, chromium, molybdenum, or cobalt.
The gas shift reaction is an industrial process in which carbon monoxide (CO) and (H2O), in the form of steam, are reacted in the presence of a catalyst to give carbon dioxide (CO2) and hydrogen (H2) as shown in the following equation:

In the process disclosed by de Bruijn et al. the gas shift reaction is used to generate the hydrogen used to rearrange the hydrocarbons within the feedstock, and also to produce excess gas which is recovered as by-products. As disclosed in Bruijn et al., the source of CO can be carbon monoxide mixed with synthesis gas or generated in-situ from the decomposition of methanol.
Synthesis gas (syngas) is a mixture of hydrogen (H2) and carbon monoxide (CO) typically in a range of ratios between about 0.9 to about 3.0. It is commonly made by the controlled combustion of methane, coal, or naphtha with oxygen to give a mixture of gases including hydrogen (H2), carbon monoxide (CO), carbon dioxide (CO2), hydrogen sulfide (H2S), carbonyl sulfide (COS), and others. It is conventional to “clean-up” the produced combustion gases to give pure synthesis gas. A critical prerequisite for the use of syngas in reactions catalyzed by transition metals is the removal of sulfur containing compounds, such as H2S or COS, formed from sulfur compounds in natural hydrocarbons or coal.
The processes disclosed by de Bruijn et al., also known as CANMET technology, suffer from significant deficiencies when practiced on an industrial scale. Specifically, the CANMET technology: lacks a suitable source for synthesis gas within the process scheme; generates waste products such as coke, heavy hydrocarbon crude oil residues, and spent catalyst that must be disposed of in an environmentally conscious manner; generates by-products highly contaminated with hydrocarbons that require significant treatment before being released to the environment; requires an economic source of heat for the upgrading/rearrangement reactions; prefers a separate sulfiding step to activate the catalysts utilized in the upgrading/rearrangement reactions; is limited by the slow kinetics of the gas shift reaction; and, has problems with the stability and breakdown of the heavy hydrocarbon crude oil and heavy hydrocarbon crude oil feedstock dispersion.
Subsequent disclosures by Khan et al in U.S. Pat. No. 5,935,419 entitled “Methods for Adding Value to Heavy Oil Utilizing a Soluble Metal Catalyst,” and U.S. Pat. No. 6,059,957 entitled “Methods for Adding Value to Heavy Oil” provide a solution to the above problems. However, these two patents involved the use of water in the feedstock along with heavy crude oil specifically to integrate the upgrading process with a gasification process. Use of water in the crude oil, while beneficial in certain gasification conditions, can create serious operating difficulties in an upgrading unit. Such difficulties include the fact that water is a scare resource in many parts of the world, particularly in Middle-East. Second, the use of water in a pressurized upgrading unit can cause serious operational challenges as water vaporizes and expands into reaction.
Therefore, one advantage of the present invention is the ability to define a better way to utilize hydrogen while processing heavy crude oil under lower operating pressure. Furthermore, the hydrogen containing gas preferably used in the upgrading process has a high purity (>90% H2), thereby improving the overall reaction chemistry. Previous upgrading processes did not address the importance of the quality of the hydrogen purity in the upgrading process, while maintaining a relative low operating pressure. This invention also teaches the benefit of oil soluble catalysts (also known as nano catalysts). Unlike heterogeneous catalysts, oil soluble homogeneous catalysts disperse well and do not precipitate during crude oil processing.
This invention is also directed to improving mass transport by premixing the gas and liquid with a dispersed catalyst prior to reactions in a well-mixed reactor system where upgrading of crude oil takes place. The upgraded product is subsequently separated and further treated to improve quality. Various fractions can then be separated and used in the most economical way. The H2S and CO2 generated during upgrading of the crude oil can also be injected into a reservoir for re-use.
The residue generated in an upgrading process is generally of low value. In addition, the evolved light gases, e.g. methane, ethane, and propane do not have high-value. One of the objectives of this invention is to use the residue along with the light gases to make these materials into value added products such as aromatics and olefins in a fluid catalytic cracking (“FCC”) unit. The FCC unit is a carbon rejection and hydrogen transfer device. The FCC process tailors the carbon distribution based on the hydrocarbon structures in the feedstock and the drive towards equilibrium in the cracking process. Historically, the FCC unit has been viewed as a relatively inexpensive gasoline and light olefin generator that now has significant application as a residual oil upgrader. The FCC unit and its constituent parts are well known in the art. Examples of FCC unit can be found in U.S. Pat. No. 2,737,479. Some FCC units can accommodate refinery residue and/or heavy oil.
Hydrocarbon catalytic cracking processes increasingly employ a system whereby the hydrocarbon feedstock is cracked in the presence of a high activity cracking catalyst in a riser-type reactor. In general, the FCC process proceeds by contacting hot regenerated catalyst with a hydrocarbon feed in a reaction zone under conditions suitable for cracking; separating the cracked hydrocarbon gases from the spent catalyst using a gross cut separator followed by conventional cyclones; steam stripping the spent catalyst to remove hydrocarbons; subsequently feeding the stripped, spent catalyst to a regeneration chamber where a controlled volume of air is introduced to burn the carbonaceous deposits from the catalyst; and returning the regenerated catalyst to the reaction zone.
Most FCC units are operated to maximize conversion to gasoline. This is particularly true when building gasoline inventory for peak season demand. Maximum conversion of a specific feedstock is usually limited by both FCC unit design constraints (i.e., regenerator temperature, wet gas capacity, etc.) and the processing objectives. However, within these limitations, the FCC unit operator has many operating and catalyst property variables to select from to achieve maximum conversion. The primary variables available to the FCC unit operator for maximum unit conversion for a given feedstock quality can be divided into two groups, catalytic variable (catalyst activity, design) and process (temperature, pressure, reaction time, extent of catalyst regeneration etc.). These variables are not always available for maximizing conversion because most FCC units are already operating at an optimum conversion level corresponding to a given feed rate, set of processing conditions, and catalyst at one or more unit constraints (e.g., wet gas compressor capacity, fractionation capacity, air blower capacity, reactor temperature, regenerator temperature, catalyst circulation). Therefore, the operator has only a few operating variables to adjust. Once the optimum conversion level is found, the operator has no additional degree of freedom for changing the operating variables. However, the operator can work with the catalyst supplier to redesign the catalyst properties to remove operating constraints to shift the operation to a higher optimum conversion level or alternatively utilize low cost feedstock that would maximizes light olefins per unit of cost of feedstock in a suitable FCC unit.
It is known in the art that for the crystalline silicates, long chain olefins tend to crack at a much higher rate than the corresponding long chain paraffins. When crystalline silicates are employed as catalysts for the conversion of paraffins into olefins, the conversion rate decreases as the time on stream increases, which is due to formation of coke (carbon) which is deposited on the catalyst. Many advanced commercially available catalysts can be used for converting a variety of feedstock in a typical FCC. The primary cracking catalysts are made of zeolite and matrix (clay and a binder). For increased production of C2 and C3 olefins, the ZSM-5 additives are also used. Typical FCC sulfur reducing additives are also applied, such as RESOLVE® (trade name) from AKZO Nobel is an example.
Known FCC processes are employed to crack heavy paraffinic molecules into lighter molecules. However, when it is desired to produce propylene, not only are the yields low, but the stability of the crystalline silicate catalyst is also low. For example, in an FCC unit a typical propylene output is 3.5 wt %. The propylene output may be increased to up to about 7-8 wt % propylene from the FCC unit by introducing the ZSM-5 catalyst into the FCC unit to “squeeze” out more propylene from the incoming hydrocarbon feedstock being cracked. Not only is this increase in yield quite small, but also the ZSM-5 catalyst has low stability in the FCC unit.
The petrochemical industry is presently facing a major squeeze in propylene availability as a result of the growth in propylene derivatives. Traditional methods to increase propylene production are not entirely satisfactory. For example, additional naphtha steam cracking units which produce about twice as much ethylene as propylene are an expensive way to yield propylene since the feedstock is valuable and the capital investment is very high. Typically, naphtha is in competition as a feedstock for steam crackers because it is a base for the production of gasoline at refineries. Propane dehydrogenation gives a high yield of propylene but the feedstock (propane) is only cost effective during limited periods of the year, making the process expensive and limiting the production of propylene. Propylene is obtained from FCC units, but at a relatively low yield. Increasing the yield has proven to be expensive and limited.
Thus there is a need for a high yield propylene production method which can readily be integrated into a refinery or petrochemical plant, taking advantage of feedstocks that are less valuable for the market place (having few alternatives on the market). The heavy residue fraction and the light off gases from an upgrading unit which contain significant amount of C2-C8 products including aromatics, olefins and naphtha are excellent feedstock for a FCC unit to produce higher value products.